Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel) or porous rock. Production of natural gas from such formations typically involves drilling a wellbore to a desired depth within the formation, installing a casing in the wellbore (to keep the wellbore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow from the formation into the casing, and installing a string of production tubing inside the casing down to the production zone. Gas can then flow to the surface through the production tubing.
Formation liquids, including water, oil, and/or hydrocarbon condensates, are typically present with natural gas in a subsurface reservoir. If the formation pressure (i.e., the pressure of the fluids flowing into the well from the formation) is high enough, it will lift the liquids with the natural gas, and the liquids can be separated from the gas in a separator facility at the surface. However, the formation pressure reduces as more gas is produced from the well, and may eventually become insufficient to lift the liquids. Liquids therefore accumulate in the well and in the production tubing, and since the density of the liquids is much higher than the density of natural gas, the hydrostatic pressure exerted by the column of liquid in the well exceeds the reduced formation pressure, thus preventing the flow of gas from the formation into the well. The well is then said to be “liquid loaded”.
Although the well may be liquid loaded, the formation pressure may still be sufficient to lift gas to the surface if the accumulated liquid in the well can be removed, and one well-known way to do that is by using a fluid lift plunger inserted into the production tubing to facilitate intermittent production from the well. Fluid lift plungers come in many different styles. In general terms, however, a fluid lift plunger can be described as a generally cylindrical body, typically made of steel, and having an outer diameter slightly smaller than the inner diameter of the production tubing; i.e., such that the plunger can move freely up and down within the tubing, and will gradually fall by gravity through any liquid that has accumulated in the tubing, but tight enough against the tubing wall to allow the plunger to support and lift a column of liquid without any significant amount of the liquid bypassing the plunger and dropping back down the tubing.
To use a plunger lift system in a liquid loaded well, a plunger is inserted into the production tubing and allowed to drop through the accumulated liquid to the bottom of the tubing. The well is then closed in (by closing a shut-off valve on the tubing at the wellhead), thereby allowing pressure in the well to build up; even though the formation pressure may have become partially depleted, it will still gradually pressurize the well, because the well has no means for pressure relief while it is closed in. When the wellbore pressure has built up to a level sufficient to overcome the hydrostatic pressure of the accumulated liquids, the well can be opened up (by opening the shut-off valve) to begin a production cycle. The plunger, sitting at the bottom of the column of liquid in the production tubing, thus becomes exposed to the built-up wellbore pressure, which forces the plunger upward, lifting the liquid column with it.
When the column (or “slug”) of liquid reaches the wellhead, it is drawn off through a production flow line above the shut-off valve, while the plunger continues upward into a “lubricator”, which is essentially an extension of the production tubing extending above the flow line. With the liquid thus removed from the production tubing, thereby relieving the hydrostatic pressure on the formation, the well has been “unloaded”. Gas can once again be produced up the tubing until such time as the formation pressure drops and the well becomes liquid loaded again, whereupon the process can be repeated by re-inserting the plunger and closing off the well to let the wellbore pressure build up again.
The lubricator serves as a receiver for the plunger when it arrives at the surface after the well has been opened up. A lubricator typically incorporates a spring-loaded “bumper” or other means at its upper end for cushioning the arrival of the plunger, which can be moving upward quite fast by the time it reaches the lubricator. As well, the lubricator will incorporate a “catcher” which prevents the plunger from falling back down the tubing, and which allows the well operator to retrieve the plunger. One common type of catcher comprises a spring-loaded member (conventionally referred to as a “bullet”) that projects into the bore of the receiver but is readily displaced radially outward when contacted by the upward-travelling plunger, thereby allowing the plunger to continue its upward travel. The spring-loaded bullet immediately moves back into the lubricator bore. When the plunger reaches the end up its upward travel (usually by hitting the cushioning spring), it drops down and rests on the bullet. An end cap at the upper end of the lubricator can now be removed to allow retrieval of the plunger for examination and servicing as required.
When the time comes to open a closed-in well and begin a new production cycle, the plunger is re-inserted into the lubricator so that it rests on the bullet, and the end cap is tightened onto the upper end of the lubricator. The shut-off valve is opened, and the bullet is retracted from the lubricator bore (by means of an external actuator) to allow the plunger to drop down past the shut-off valve into the production tubing.
Many examples of lubricators, plunger “bumpers” and catchers can be found in the prior art; see, for example, U.S. Pat. Nos. 6,148,923 and 6,705,404.
For a number of reasons, lubricators commonly extend several feet above the catcher. One reason for this is to accommodate different types of plungers, the lengths of which can vary significantly. In any event, it is common for the upper end of a plunger, resting on or in the catcher, to be disposed a considerable distance below the top of the lubricator, thus making it difficult to retrieve the plunger. The upper end of a typical plunger is formed with a heavy cylindrical flange commonly called a “fishing neck”, with a diameter smaller than the main body of the plunger so that it can be grasped (either manually or with a “fishing” tool of some type) to retrieve or “fish” the plunger from the lubricator. However, this is not always easy to do when the plunger is sitting well down into the lubricator.
Installation of a plunger into a lubricator must also be done with care to prevent damage to wellhead components. Particularly in the case of a wellhead having a comparatively long lubricator, a heavy plunger that is simply dropped into the lubricator from a significant height above the catcher can displace or pass through the catcher and then impact the shut-off valve, causing physical damage to the catcher or the valve or both. Accordingly, it is desirable to insert a plunger into a lubricator in a manner that sets the plunger onto the catcher with minimal vertical force, so that the catcher will not be displaced or damaged in the process.
For the foregoing reasons, there is a need for improved tools for inserting a fluid lift plunger into the lubricator on a gas wellhead and for retrieving the plunger from the lubricator.